Subterranean drilling typically involves rotating a drill bit from surface or on a downhole motor at the remote end of a tubular drill string. It involves pumping a fluid down the inside of the tubular drill string, through the drill bit, and circulating this fluid continuously back to surface via the drilled space between the hole/tubular, referred to as the annulus. For a subsea well bore, a tubular, known as a riser extends from the rig to the top of the wellbore which exists at subsea level on the ocean floor. It provides a continuous pathway for the drill string and the fluids emanating from the well bore. In effect, the riser extends the wellbore from the sea bed to the rig, and the annulus also comprises the annular space between the outer diameter of the drill string and the riser.
This pumping mechanism is provided by positive displacement pumps that are connected to a manifold which connects to the drill string, and the rate of flow into the drill string depends on the speed of these pumps. The drill string is comprised of sections of tubular joints connected end to end, and their respective outside diameter depends on the geometry of the hole being drilled and their effect on the fluid hydraulics in the wellbore.
The entire drill string and bit are rotated using a rotary table, or using an above ground motor mounted on the top of the drill pipe known as a top drive. The bit can also be turned independently of the drill string by a drilling fluid powered downhole motor, integrated into the drill string just above the bit.
As drilling progresses pipe has to be connected to the existing drill string to drill deeper. Conventionally, this involves shutting down fluid circulation completely so the pipe can be connected into place as the top drive has to be disengaged.
The large diameter sections that exist at the end of each section of drillpipe are referred to as tool joints. During a connection, these areas provide a low stress area where the rig pipe tongs or Iron Roughneck can be placed to grip the pipe and apply torque to either make or break a connection.
Conventionally, the well bore is open to atmospheric pressure and there is no surface applied pressure or other pressure existing in the system. The drill string rotates freely without any sealing elements imposed or acting on the drill string at the surface, and there is no requirement to divert the return fluid flow or exert pressure on the system during these standard operations.
Managed pressure drilling and/or underbalanced drilling utilizes additional special equipment that has been developed to keep the well closed at all times, as the wellhead pressures in these cases are non-atmospheric, as in the traditional art of the conventional overbalanced drilling method.
The invention is particularly useful in an operating system with a well having a drilling fluid circulating within a closed loop system. The closed loop is generated by a seal around the drill pipe at surface using a pressure containment device, diverting all returned flow to a flow line. These are referred to as a rotating control head (RCD or RCH), pressure control while drilling (PCWD) or rotating blow out preventer (RBOP). The function of the rotating pressure containment device is to allow the drill string and its tool joints to pass through with reciprocation/stripping or rotation. With drilling activity in progress and the device closed a back pressure is created on the annulus. The drill string is stripped or rotated through the sealing element(s) pressure containment device which isolates the pressurized annulus from the external atmosphere while maintaining a pressure seal around the drill pipe. All are standard equipment that are commercially available or readily adaptable from existing designs on the market and are well known in the art.
A typical sealing element in existing pressure containment designs includes an elastomer or rubber packing/sealing element and a bearing assembly that allows the sealing element to rotate along with the drill string. There is no rotational movement between the drill string and the sealing element, and only the bearing assembly exhibits the rotational movement during drilling. These are well known in the art and are described in detail in Patents U.S. Pat. No. 7,699,109B2, U.S. Pat. No. 7,926,560, and U.S. Pat. No. 6,129,152.
An alternative pressure containment device is disclosed in WO2011128690 and WO2012127227. This device includes a combined non-elastomeric and elastomeric sealing element, referred to as the seal sleeve, which does not rotate with the drill string, i.e., it remains stationary while the drill string is rotated and reciprocated within the sealing face.
Drill string rotation and vertical movement wears out the sealing elements, and the passage of tool joints and larger OD tubulars causes the sealing element to expand and contract multiple times. Replacement requires the drilling operation to stop and therefore lowers the well performance, and the replacement frequency for sealing assemblies varies with wellbore pressure, temperature, fluid composition, and stripping/rotating frequency over the drilling and tripping phases. Therefore a wear monitoring system for the sealing elements will allow the wear rate to be examined over these varied conditions as the element degrades and reduces in thickness, indicating when the sealing element should be replaced. This results in a much safer and efficient operation on the drilling platform.
Additionally, there are hazards and risks associated with uncertainty in the degree of wear of the sealing element(s) in the housing. There are no indications that the sealing element is failing, and generally they leak when they fail while in operation. A consequential uncontrolled pressure release occurs, carrying with it drilling fluids, cuttings, and possibly gas into the working atmosphere of the rig. This poses both environmental and workplace hazards to personnel and equipment that could be eliminated if a wear monitoring system was in place.
Typically, a dual sealing arrangement for an RCD monitors the pressure between the two sealing elements. A pressure differential exists between the cavity of the sealing elements and the wellbore pressure below. It is known to monitor continuously the pressure between the elements, and when the pressure starts to increase, take this as a positive indicator that the lower sealing element is failing.
This method is not suitable for accurately monitoring the wear of the upper sealing element, however. Furthermore, there are no systems or methods for monitoring the wear occurring on the inner bore sealing area, nor the thickness of the sealing material remaining within a single element arrangement in the prior art. Detection is solely through visual leak paths through the sealing elements that will result in pressure releases to the atmosphere.